Underground drilling, such as gas, oil, or geothermal drilling, generally involves drilling a bore through a formation deep in the earth. Such bores are formed by connecting a drill bit to long sections of threaded pipe, referred to as a “drill pipe,” so as to form an assembly commonly referred to as a “drill string.” The drill string extends from the surface to the drill bit at the bottom of the bore. The lowermost portion of the drill string is referred to as the bottom hole assembly.
The drill bit is rotated so that the drill bit advances into the earth, thereby forming the bore. In rotary drilling, the drill bit is rotated by rotating the drill string at the surface. Piston-operated pumps on the surface pump high-pressure fluid, referred to as “drilling mud,” through an internal passage in the drill string and out through the drill bit. The drilling mud lubricates the drill bit, and flushes cuttings from the path of the drill bit. In the case of motor drilling, the flowing mud also powers a drilling motor which turns the bit, whether or not the drill string is rotating. The drilling mud then flows to the surface through an annular passage formed between the drill string and the surface of the bore.
Drill rig operators typically vary three parameters in order to optimize the rate of penetration of the drill bit into the rock and the vibration to which the drill string is subjected—(i) the rotary speed of the drill bit, (ii) the axial force driving the drill bit into the formation, referred to as the weight on bit (“WOB”), and (iii) the flow rate of the drilling mud. Although, increasing the WOB may increase the rate of penetration of the drill bit into the formation, it can also lead to inefficient rock cutting and excessive vibration, which can shorten the life of the bottom hole assembly components.
It is important, therefore, that the operator have accurate information concerning the magnitude of the WOB. An estimate of WOB may be obtained at the surface based on the difference between the known weight of the drill string and the hook load—that is, the tension of the drill string suspended from the derrick—corrected for the buoyant force of the drilling mud and a calculation of the drag. The calculation of drag experienced by the drill string is subject to inaccuracies, particularly in inclined or horizontal wells. Preferably, the WOB can be measured downhole, near the drill bit, by incorporating strain gauges into the bottom hole assembly. A system for measuring WOB using downhole strain gauges is described in U.S. Pat. No. 6,547,016, entitled “Apparatus For Measuring Weight And Torque An A Drill Bit Operating In A Well,” hereby incorporated by reference herein in its entirety. Unfortunately, the output of the strain gauges can be affected by pressure and temperature, which can also lead to inaccuracies in the measurement of WOB.
Therefore, a need exists for an apparatus that can quickly and accurately measure the WOB during drilling.
The useful life of the components in the bottom hole assembly may depend on the stress levels to which such components are subjected as a result of vibration. Therefore, it would also be useful to provide the operator with information concerning the maximum stress levels being experienced by the bottom hole assembly.